1. Field of the Invention
The present invention relates to fluid flowrate determination, and more particularly to the determination of flowrates for hydrocarbons flowing through one or more portions of a producing wellbore. The invention has particular application in horizontal wellbores and in wellbores having multiple producing zones.
2. Background of the Related Art
Flowrate determination, particularly mass flowrate determination, is an important function in the efficient management of hydrocarbon production from producing subsurface formations (also known as reservoirs). Real time or near-real time flowrate determination is particularly valuable in the diagnosis and remediation of production problems. The overall mass flowrate through conventional, producing wellbores can easily be determined at the wellhead using known methods. Obtaining a more detailed understanding of the flow from various downhole portions of a wellbore, however, is more difficult and requires making measurements within the wellbore itself. Prior methods for determining fluid flowrates downhole, particularly in multiple producing zones and in horizontal wellbore segments, have not been entirely satisfactory.
U.S. Pat. No. 5,610,331, to Western Atlas, describes a method for determining a flow regime of fluids in a conduit. The method generates a temperature map of the conduit through the use of a plurality of distributed temperature sensors and a means for determining the position of each one of the sensors within the cross-section of the conduit. A flow regime is determined by comparing the temperature map with a map generated from laboratory experiments in a flow loop. The system of the '331 patent is limited by its requirement for a distributed temperature profile, including a plurality of temperature indications along a wellbore.
U.S. Pat. No. 6,618,677 to Sensor Highway describes a fiber optic sensor system for determining the mass flowrates of produced fluid within a conduit disposed in a wellbore. According to the specification, fluid produced through the wellbore conduit (production tubing) generally exhibits a relatively high temperature. The subsurface formation(s) that the wellbore extends through are generally at a lower temperature than the reservoir from which the produced fluid originated. As the produced fluid passes upwardly through the wellbore conduit past the cooler, surrounding subsurface formation(s), the fluid is said to cool. A fiber optic sensor system is employed to monitor this cooling over a length of the conduit and to generate a distributed temperature profile. The generated distributed temperature profile is compared with a previously-determined temperature-flowrate calibration to determine a mass flowrate of fluids within the wellbore conduit. The system of the '677 patent is therefore also limited by a need to acquire measurements at a plurality of locations along the length of the wellbore conduit.
U.S. Pat. No. 6,769,805, also to Sensor Highway, describes a method of using a heater cable equipped with a fiber optic distributed temperature sensor to determine fluid flowrate within a wellbore. The cable is heated to a temperature above the temperature of the wellbore in which it is positioned, and then de-energized so as to cool under the flow of produced fluid through the wellbore. The fiber optic distributed temperature sensor is employed to generate a distributed temperature profile along the heater cable. The '805 patent suggests that the generated profile may be correlated to the fluid flowrate, within explaining how to achieve this. U.S. Pat. No. 6,920,395, also to Sensor Highway, is similar to the '805 patent except it employs a heat sink (rather than temporary, active heating) to induce cooling of a fiber optic distributed temperature sensor. The systems of the '395, '805, '677 and '331 patents are therefore all limited to flowrate correlations based upon distributed temperature profiles.
U.S. Pat. No. 6,766,854 to Schlumberger describes a system for obtaining downhole data from a subsurface formation penetrated by a wellbore bore, and is characterized by the use of a sensor plug positioned in the sidewall of a wellbore, and separate downhole tools for installing and communicating with the plug. The system of the '854 patent is limited by the permanent nature of the sensor plug and the complexity of installing and establishing communication with it, possibly across a casing wall.
U.S. Pat. No. 6,817,257 to Sensor Dynamics describes an apparatus and a method for remote measurement of physical parameters involving an optical fiber cable sensor and a cable installation mechanism for installing the optical fiber cable within a specially-configured conduit. The installation mechanism includes a means for propelling a fluid along the conduit so as to deploy the optical fiber cable sensor, and a seal assembly between the optical fiber cable and the conduit. The '257 patent mentions that its “sensor” can be a flow sensor “based on combining the outputs from more than one sensor and applying an algorithm to estimate flow” but does not explain how this may be achieved.
The flowrate-determining solutions mentioned above are therefore characterized by systems requiring the development of a distributed temperature profile over a length of the wellbore, and systems requiring permanent installation and potentially difficult communication with downhole sensors. A need therefore exists for a flowrate-determining solution that is adaptable to being used in a multitude of downhole locations, not restricted by the need for a distributed sensing length.
A need further exists for a flowrate-determining solution that facilitates easy installation—temporary or permanent—but is not encumbered by a need for permanent installation. Adaptability in the installation of a flowrate-determining solution will facilitate its application in wellbores having multiple producing zones as well as horizontal wellbore sections, including horizontal “legs” of so-called multilateral wellbores. Horizontal wellbore bore sections are typically fluidly-connected to a vertical wellbore section that extends to the surface. By way of example, it is of considerable interest to a drilling engineer (in the case of wellbore drilling) or a production/reservoir engineer (in the case of wellbore production) whether a portion of the horizontal wellbore section near the vertical section is producing at a much higher volumetric flowrate, at about the same rate, or at a much lower rate, than a portion of the horizontal wellbore section that is far from the vertical wellbore section.